Ammonia destruction methods for use in a claus tail gas treating unit

ABSTRACT

Oxidative and reductive methods are described for the cost-effective destruction of an ammonia-bearing gas stream, potentially containing minor but significant quantities of hydrogen sulfide (H 2 S), in a conventional Claus sulfur recovery tail gas treating unit, using controlled rates and compositions of combustion gases in order to obtain the temperatures necessary for the desired destruction of unwanted combustibles. In accordance with the present disclosure, a reductive method for the destruction of ammonia in a Claus tail gas treating unit is described, wherein the method includes introducing an ammonia-containing gas stream into a first combustion zone of a reactor in combination with a first oxygen-containing air stream to generate a first combustion gas stream composition; introducing a hydrocarbon-containing fuel gas stream and a second oxygen-containing air stream into a second combustion zone of the reactor to generate a second combustion gas stream composition; combining the first and second combustion gas stream compositions in a waste heat boiler to generate a waste effluent gas; contacting the waste effluent gas with a Claus tail gas stream to produce a primary waste stream; and contacting the primary waste stream with a hydrogenation catalyst system for a period of time sufficient to reduce NO x  in the primary waste stream to ammonia.

CROSS REFERENCE TO RELATED APPLICATIONS

The present application claims priority to U.S. Provisional PatentApplication Ser. No. 60/910,074, filed Apr. 4, 2007, the contents ofwhich are incorporated herein by reference.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

REFERENCE TO APPENDIX

Not applicable.

BACKGROUND OF THE INVENTION

1. Field of the Invention

This disclosure relates generally to methods for the destruction ofunwanted byproducts in tail gas treating units, and more particularly,to methods for the destruction of byproduct ammonia gas in Claus tailgas treating units associated with Claus reactor units.

2. Description of the Related Art

The “modified. Claus” process is commonly employed for the recovery ofelemental sulfur from byproduct hydrogen sulfide (H₂S) gas produced invarious industrial sectors, most notably natural gas production andpetroleum refining. This recovered elemental sulfur may be used in avariety of applications, including the production of sulfuric acid.Conversion from byproduct hydrogen sulfide generally begins with acontrolled combustion with oxygen (O₂), typically as air, in whichapproximately ⅓ of the H₂S is oxidized to sulfur dioxide (SO₂), asillustrated in equation (1):

H₂S+3/2O₂→SO₂+H₂O+ΔH[combustion]  (1)

The SO₂ so generated then reacts with the remaining hydrogen sulfide(H₂S) to form sulfur and water vapor according to the Claus reaction asshown in equation (2):

2H₂S+SO₂→3S+2H₂O+ΔH  (2)

In summation, the net overall reaction for the recovery of elementalsulfur from by-product hydrogen sulfide (H₂S) may be described as shownin equation (3), below. Roughly half of the sulfur produced in such amanner is formed in the reaction furnace, with the balance typicallybeing generated by continuation of reaction (2) in one or moredownstream catalytic stages.

3H₂S+3/2O₂→3S+3H₂O+ΔH  (3)

The refining processes conducive to formation of byproduct H₂S from morecomplex organic sulfur compounds also tend to convert nitrogen compoundsto ammonia (NH₃). Subsequent recovery of the NH₃ will typically yield aroughly equimolar gaseous mixture of NH₃ and H₂S (and water), whichusually can be conveniently fed to the Claus reaction furnace incombination with a larger H₂S stream containing negligible NH₃. The NH₃is ostensibly oxidized as shown in equation (4).

2NH₃+3/2O₂→N₂+3H₂O+ΔH  (4)

However, since the oxygen (O₂) used is nominally limited to thatrequired for oxidation of only ⅓ of the hydrogen sulfide, the hydrogensulfide and ammonia are in competition for the available O₂ such thatinitial SO₂ generation likely exceeds that required by the Clausstoichiometry, and much of the ammonia is subsequently oxidized togenerate nitrogen gas and water by reaction with SO₂ as shown inequation (5).

4NH₃+3SO₂→2N₂+6H₂O+1.5S₂[conversion]  (5)

In Claus reactions, exactly one third of the feed sulfur must beoxidized to SO₂, requiring close control of the supply of oxygen inexcess of that consumed by other reactions, including the combustion ofhydrocarbons and ammonia. Fluctuations in the rate of ammonia additioninto the feed may therefore have an unwanted, disproportionate effectupon the oxygen demand. Clearly then, the amount of vapors containingammonia and hydrogen sulfide which can be treated in this manner islimited, and it is generally accepted that the maximum amount of ammonia(NH₃) that can be so processed is about 30-35% of the total Claus feed,on a wet basis. Several processes for the treatment of vapors containingammonia and hydrogen sulfide so as to address these issues andlimitations are known and have been described in the art.

For example, a unique furnace design, which permits the combustion ofproportionately greater amounts of NH₃, has been described in U.S. Pat.No. 5,904,910. This patent suggests a method for producing hydrogen andsulfur from a first gaseous mixture containing hydrogen sulfide andammonia by separating ammonia from the first gaseous mixture to producea second gaseous mixture containing hydrogen sulfide; combusting aportion of the hydrogen sulfide in the second gaseous mixture to producea third gaseous mixture containing hydrogen sulfide and sulfur dioxide;heating the ammonia to a temperature of at least 1800° F. to produce afourth gaseous mixture containing nitrogen and hydrogen; and, combiningthe third gaseous mixture and the fourth gaseous mixture and passing thecombined gaseous mixture to a sulfur recovery process wherein thehydrogen sulfide and sulfur dioxide are recovered as sulfur. The ammoniamay be partially oxidized by the use of substoichiometric amounts ofoxygen or thermally dissociated. Other options which have been suggestedfor addressing this problem include conversion of the NH₃-bearing streamto ammonium thiosulfate fertilizer, and purification of the NH₃ formarketing as a byproduct or incineration.

Other approaches in addressing this problem have included, thecontrolled injection of gas injections into a Claus furnace usingparallel injections and injection speeds, using modified catalysts,using gas permeable membranes and specialized treatment solutions, andusing sensors such as laser diodes at the outlet of a Claus furnace inorder to control the flow rate of gasses and minimize the amount ofoxygen-rich gas required by the process. More recently, approaches usingspecialized burner designs having specific tube orientations anddiameters in order to at least partially oxidize gas streams comprisinghydrogen sulfide and ammonia, such as described in U.S. Pat. No.6,890,498 to Tsiava, et al.

In view of these problems with the production and control of ammoniaduring Claus productions, improved methods for the clean, safe andefficient destruction of ammonia in tail gas treating units arenecessary. This application for patent discloses methods for theefficient and environmentally favorable treatment of vapors whichcontain ammonia for the destruction of the ammonia in Claus tail gastreating units.

BRIEF SUMMARY OF THE INVENTION

In accordance with the present disclosure, the present disclosureprovides methods for the efficient treatment and destruction of ammoniain Claus tail gas treating units. In accordance with one embodiment ofthe present disclosure, a reductive method for the destruction ofammonia in a Claus tail gas treating unit is described, wherein themethod comprises introducing an ammonia-containing gas stream into afirst combustion zone of a reactor in combination with a firstoxygen-containing air stream to generate a first combustion gas streamcomposition; introducing a hydrocarbon-containing fuel gas stream and asecond oxygen-containing air stream into a second combustion zone of thereactor to generate a second combustion gas stream composition;combining the first and second combustion gas stream compositions in awaste heat boiler to generate a waste effluent gas; contacting the wasteeffluent gas with a Claus tail gas stream to produce a primary wastestream; and contacting the primary waste stream with a hydrogenationcatalyst system for a period of time sufficient to reduce NO in theprimary waste stream to ammonia.

In accordance with a separate embodiment of the present disclosure, anoxidative method for the destruction of ammonia in a Claus tail gastreating unit is described, the method comprising introducing anammonia-containing gas stream into a first combustion zone of a reactorin combination with a first oxygen-containing air stream to generate afirst combustion gas composition; introducing a hydrocarbon-containingfuel gas stream and a second oxygen-containing air stream into a secondcombustion zone of the reactor to generate a second combustion gascomposition; combining the combustion gases in a third combustion zoneof the reactor to generate a third combustion gas composition; andcombining the third combustion gas composition with a Claus tail gasstream in a fourth combustion zone of a reactor to generate a reactiontemperature capable of thermally oxidizing combustibles within thefourth combustion zone.

BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS

The following figures form part of the present specification and areincluded to further demonstrate certain aspects of the presentinvention. The invention may be better understood by reference to one ormore of these figures in combination with the detailed description ofspecific embodiments presented herein.

FIG. 1 is a schematic diagram illustrating the destruction of byproductNH₃ in a typical reductive Claus tail gas treating unit.

FIG. 2 is a schematic diagram illustrating the destruction of byproductNH₃ in a typical oxidative Claus tail gas treating unit.

While the inventions disclosed herein are susceptible to variousmodifications and alternative forms, only a few specific embodimentshave been shown by way of example in the drawings and are described indetail below. The figures and detailed descriptions of these specificembodiments are not intended to limit the breadth or scope of theinventive concepts or the appended claims in any manner. Rather, thefigures and detailed written descriptions are provided, to illustratethe inventive concepts to a person of ordinary skill in the art and toenable such person to make and use the inventive concepts.

DEFINITIONS

The following definitions are provided in order to aid those skilled inthe art in understanding the detailed description of the presentinvention.

The term “nitrogen oxide” (NO_(x)), as used herein, refers to any of thevarious nitrogen oxides produced during combustion processes, includingbut not limited to nitric oxide (NO), nitrogen dioxide (NO₂), nitrousoxide (N₂O), dinitrogen trioxide (N₂O₃), dinitrogen tetroxide (N₂O₄),and dinitrogen pentoxide (N₂O₅). The general term NO may be used to meanthe total concentration of NO plus NO₂, as appropriate.

As used herein, the term “air” refers generally to the mixture of gasessurrounding the earth's atmosphere, comprising nitrogen, oxygen, argon,carbon dioxide, helium, neon, hydrogen, and methane, in varied amounts.

As used herein, the term “gas rich in oxygen” refers to air which hasbeen enriched in its oxygen content, such that the oxygen content isgreater than about 25 molar percent (mol %), up to about 100 mol %, aswell as oxygen contents having mol % values between such values, whereinsuch a gas enriched to contain 100 mol % oxygen corresponds to pureoxygen gas. The content of oxygen in which the gas enriched in oxygencorresponds to the molar fraction of oxygen in the enriched gas. Forexample, air that has been enriched in oxygen to 50% consists of a gasmixture comprising 50 molar percent oxygen.

DETAILED DESCRIPTION

The Figures described above and the written description of specificstructures and functions below are not presented to limit the scope ofwhat Applicants have invented or the scope of the appended claims.Rather, the Figures and written description are provided to teach anyperson skilled in the art to make and use the inventions for whichpatent protection is sought. Those skilled in the art will appreciatethat not all features of a commercial embodiment of the inventions aredescribed or shown for the sake of clarity and understanding. Persons ofskill in this art will also appreciate that the development of an actualcommercial embodiment incorporating aspects of the present inventionswill require numerous implementation-specific decisions to achieve thedeveloper's ultimate goal for the commercial embodiment. Suchimplementation-specific decisions may include, and likely are notlimited to, compliance with system-related, business-related,government-related and other constraints, which may vary by specificimplementation, location and from time to time. While a developer'sefforts might be complex and time-consuming in an absolute sense, suchefforts would be, nevertheless, a routine undertaking for those of skillthis art having benefit of this disclosure. It must be understood thatthe inventions disclosed and taught herein are susceptible to numerousand various modifications and alternative forms. Lastly, the use of asingular term, such as, but not limited to, “a,” is not intended aslimiting of the number of items. Also, the use of relational terms, suchas, but not limited to, “top,” “bottom,” “left,” “right,” “upper,”“lower,” “down,” “up,” “side,” and the like are used in the writtendescription for clarity in specific reference to the Figures and are notintended to limit the scope of the invention or the appended claims.

In general terms, Applicants have created an ammonia combustion systemin order to substantially destroy the ammonia in Claus reactor wastestreams, and in so doing minimize nitrogen oxide (NO_(x)) formationwhile simultaneously maximizing hydrogen gas (H₂) production. Thepresently described systems, which are alternatively oxidative orreductive, uniquely integrate ammonia combustion with the thermal gastreating unit (TGU) feed preheating step, and simultaneously controlsand optimizes the air/NH₃ ratio in order to minimize NO and maximize H₂by virtue of accepting incomplete NH₃ destruction.

In the context of the present disclosure, the use of the term“reductive” in association with the ammonia destruction processesdescribed herein refers to the general class of thermal gas treatingunits (TGU), wherein all non-H₂S sulfur compounds are reduced to H₂S.This is in contrast to an “oxidative” TGU whereby all non-SO₂ sulfurcompounds are oxidized to SO₂.

For units processing substantial amounts of ammonia (NH₃), Claus sulfurrecovery efficiency is typically <95% and secondary treatment may oftenbe necessary in order to meet emission limits. There are fundamentallytwo types of Claus tail gas treating units (TGUs) which can beused—reductive TGUs and oxidative TGUs.

The most prevalent are reductive units, which catalytically convertvirtually all non-H₂S sulfur compounds and elemental sulfur vapor(S_(x)) to H₂S for (1) subsequent absorption in a regenerable solution,typically an alkanolamine, for recycle to the Claus unit, or (2)precipitation of elemental sulfur particles in a redox process.

Oxidative TGUs thermally oxidize all sulfur compounds and S_(x) to SO₂for subsequent absorption in a regenerable solution for recycle to theClaus unit.

In conventional Reducing Gas Generator (RGG) processes, the tail gasfrom the final condensers of the sulfur recovery units enters thehydrogenation section through the Reducing Gas Generator. The reducinggas generator has the dual purpose of heating the tail gas to atemperature that will permit the desired hydrogenation and hydrolysisreactions to proceed in the reactor and to supply reducing gases, H₂ andCO, to supplement those present in the tail gas. These functions arecarried out by the combustion of natural gas with air supplied by theRGG combustion air blower at substoichiometric conditions. Hotcombustion products are mixed with the tail gas, and the resultingstream flows to the hydrogenation reactor.

In the hydrogenation reactor, sulfur compounds are converted to H₂S bythe hydrogenation and hydrolysis reactions described above. Thesereactions are exothermic creating a temperature rise across the catalystbed.

Turning now to the figures, and particularly FIG. 1, in methods for thedestruction of ammonia in a reductive Claus tail gas treating unit(TGU), a general reductive method using a standard TGU system (10) isillustrated in FIG. 1. As shown therein, a byproduct NH₃ gas stream(12), potentially containing minor but significant concentrations ofH₂S, mercaptans, HCN, hydrocarbons and unspecified organic contaminantsis combusted sub-stoichiometrically with a stream of air (14) in wasteheat boiler (22) to generate usable heat, e.g., as steam (24) andhydrogen (H₂) gas. In a preferred embodiment, an auxiliary fuel stream(16) comprising at least one hydrocarbon, such as natural gas forexample, is also introduced into waste heat boiler (22) and combusted tothe extent potentially necessary to satisfy downstream process demandfor heat and H₂, where said auxiliary fuel is preferably combusted inzone 1 (21 a) of the combustion chamber, and the NH₃ gas is combusted indownstream zone 2 (21 b). In passing through the waste heat boiler, thecombined gas stream, comprising the combusted auxiliary fuel (16) andthe ammonia-gas (12) may be optionally passed over or contacted with anammonia (NH₃) cracking catalyst 26 before proceeding to the tail end(25) of the boiler. Further, combustion air or O₂ of the auxiliary fuelmay be sub-substoichiometric, stoichiometric or super-stoichiometric,realizing that super-stoichiometric combustion may not be generallyadvisable in all instances, especially in the absence of downstream NH₃combustion.

The combined combustion gases are subsequently combined with the Claustail gas (20) at the tail end (25) of boiler (22) to achieve a netcombustion temperature ranging from about 550° F. (about 288° C.) toabout 650° F. (about 343° C.). Following the combination of thecombustion gas stream from the boiler (22) with the Claus tail gasstream (20), the waste stream (28) is typically passed through ahydrogenation reactor (30) or the like containing an appropriatecatalyst system, such as a fixed bed of alumina catalyst which has beenimpregnated with oxides of cobalt or nickel and molybdenum. The catalystsystem serves to hydrogenate SO₂ and S_(x) vapor to H₂S, hydrolyze COSand CS₂ to H₂S, hydrolyze CO to CO₂ and H₂, and reduce NO_(x) to NH₃.From hydrogenation reactor (30), the reduced tail gas stream (31 a)proceeds through waste heat boiler (32), wherein steam (33) is released,and which may be utilized as usable heat.

The approach to stoichiometric air for the combustion of the NH₃, andpotentially the auxiliary fuel, is limited as necessary to generatesufficient H₂ for complete hydrogenation of SO₂ and S_(x) to H₂S.Consistent with established practice, a typical residual H₂concentration of from about 1% to about 3% on a dry, molar basis ismaintained downstream of the reactor.

From waste heat boiler (32), the reactor effluent gas (31 b), nominallycomprised of about ⅓ water vapor, is transferred to a contact condenser(34) and optionally directed to a sour water treatment facility, cooled,and/or passed through condenser (34) and passed through H₂S enrichmentblower (36) and reheater (38) before being re-introduced into theammonia-gas stream (12) being introduced to the reductive system (10).In the event that reactor effluent gas stream (31 b) is cooled incontact condenser (34), the cooling may be achieved by optionallycooling to a first temperature ranging from about 300° F. (about 149°C.) to about 350° F. (about 177° C.) by indirect waste heat steamgeneration, then reduced further to a second temperature ranging fromabout 80° F. (about 27° C.) to about 100° F. (about 38° C.) by directcontact with a recycle water stream (41) in the contact condenser (34),which also serves to condense most of the water vapor and absorbsubstantially all of any remaining NH₃ which may be present. Surplusrecycle water (35) may be continuously purged to the plant's sour waterblowdown collection system.

The cooled, relatively dry gas is then typically contacted with asuitable absorption medium for recovery of a majority (greater thanabout 75%) of the H₂S. In the common case where the absorption medium isan alkanolamine solution (or the like), for example, any NH₃ notabsorbed in the contact condenser (34) will be absorbed by the amine andultimately concentrated in the regenerator reflux (40), a slipstream ofwhich can be purged to sour water if necessary in order to avoidexcessive buildup.

An alternative and equally acceptable method of destroying excessammonia from Claus processes is by an oxidative method, using a system(50) as illustrated generally in FIG. 2. As shown therein, in anoxidative treating gas unit (TGU) 50 (FIG. 2), the aforementionedbyproduct ammonia gas (NH₃) stream (56) is combustedsub-stoichiometrically in a first zone, e.g., zone 1 (62), of a reactor(60), in the presence of an air/oxygen stream (58). During the reactionin zone 1 (62), the air/gas ratio may be automatically adjusted asnecessary in order to achieve a residual hydrogen (H₂) concentrationthat is sufficient to ensure that NO formation is minimized.

Simultaneously, and in accordance with this aspect of the disclosure,supplemental fuel gas (52), typically a hydrocarbon gas or refinery fuelgas, is combusted with excess air or oxygen-enriched air stream (54) ina second zone, e.g., zone 2 (64), in the reactor (60) to the extentnecessary to achieve the desired downstream temperature of the Claustail gas. When no supplemental heat is required, a minimum standby fireis preferably maintained within the appropriate zone(s) (i.e., zone 2)of the reactor (60) so that the firing rate can be promptly increased inthe event of NH₃ gas curtailment.

Following the initial combustion steps, the combustion gases from thefirst and second zones in the reactor (60) (zone 1 (62) and zone 2 (64))are combined in a third reaction zone, zone 3 (66) of reactor (60),wherein residual hydrogen gas (H₂) and potential CO (carbon monoxide),H₂S (hydrogen sulfide) and other miscellaneous combustibles can bethermally oxidized by excess O₂ from zone 2 (64).

With continued reference to FIG. 2, following the combination in thethird reaction zone, zone 3 (66), combustion effluent gases (68) exitreactor (60) and are then combined with the Claus tail gas stream (59)in a fourth zone, zone 4 (72), for a duration sufficient to achieve thenet average temperature necessary for the desired oxidation ofcombustibles within the stream, which will typically include, but is notlimited to, H₂S, S_(x), COS, CS₂ and CO. In accordance with the presentdisclosure, this fourth zone, zone 4 (72), may be in a separate reactor(70) as illustrated, or may optionally and equally acceptably becontained within a separate zone of the first reactor (60) whichcontains the first three zones, zones 1, 2 and 3. The temperaturerequired for this thermal oxidation step in the fourth zone, zone 4(72), will typically range from about 800° F. (about 427° C.) to about2000° F. (about 1093.3° C.), and more typically from about 800° F.(about 427° C.) to about 1500° F. (about 815.5° C.), depending onprevailing environmental regulations, residence time and the nature andconcentration of key combustibles. If necessary, additional combustionair (not shown) may be injected to supplement residual oxygen in thethird reaction zone, zone 3 (66), effluent. In accordance with certainaspects of the present disclosure, a typical target would be from about1 mol. % to about 5 mol. % residual O₂ on a molar wet basis, and moretypically from about 1 mol. % to about 3 mol % residual O₂ on a molarwet basis in the combined tail gas stream. The effluent stream (74),upon leaving zone 4 (72) may then be directed as desired, such as to awaste heat boiler (not shown) or a similar assembly.

Destruction of ammonia requires proper distribution of sulfur betweenthe first chamber in the thermal reactor and the second. Too littlehydrogen sulfide in the first chamber allows for the generation of hightemperatures that produce unwanted SO₃, which can deposit in or on theClaus catalyst. Conversely, too much hydrogen sulfide to the firstchamber can prevent the oxidizing atmosphere required for completedestruction of the ammonia. The residual ammonia may then be depositedin or on the catalyst. Low residual oxidizing potential also depositscoke in the reactors. The life of the Claus catalyst is shortenedwhenever the air rate is either above or below optimum.

The process gas leaving the hydrogenation reactor may be subjected tofurther processing. In a preferred embodiment of the invention, thecooled process gas in the hydrogenation reactor is brought into contactwith a hydrogenation catalyst. The hydrogenated process gas can besubjected to a selective absorption process thereby removing thehydrogen sulfide from the process gas.

Catalysts

Catalysts which are suitable for the minimization of NO_(x),maximization of NH₃ conversion, and/or maximization of hydrogen gas (H₂)yield, as well as ammonia splitting and/or hydrogenation are known and,in the case of the ammonia-cracking catalyst, will be catalysts whichwill permit the partial oxidation process at lower air/gas ratios. Suchcatalysts are generally well known in the art and can include nickelcatalysts, iron catalysts and/or nickel/iron catalysts, on a suitablesubstrate, as well as catalysts selected from the group consisting ofruthenium, platinum, nickel, cobalt, mixtures thereof

In accordance with certain aspects of the present disclosure, thecatalysts suitable for use with the processes described herein includethose containing one or more metals or combinations of metals of GroupVa, VIa, VIII, and the Rare Earth series of the Periodic Table, asdescribed and referenced in “Advanced Inorganic Chemistry, 6^(th) Ed.”by F. A. Cotton, et al. [Wiley-Interscience, 1999], any of which can bepresent on a suitable, conventional inorganic support material. Thepreferred catalysts for use with the processes described herein include,but are not limited to, those containing one or more of the metalsselected from the group consisting of cobalt, titanium, iron, chromium,vanadium, nickel, tungsten, germanium, zinc, cerium, and antimony, aswell as combinations of two or more of these metals, such as incobalt-molybdate (Co—Mo) catalysts. In the event that the catalyst usedin the processes of the present disclosure is a mixture of two metals,the ratio (on an atomic basis) of these metals is preferably betweenabout 10:90 and 97.5:2.5, and more particularly ranges from about 25:75to about 95:5, including ratios between these values, such as about50:50, Suitable supports for use in accordance with the catalysts andcatalyst systems useful in the processes of the present disclosureinclude ceramic materials, sintered metals, oxides, activated alumina oralumina-based materials, and silica gel, as well as mixtures thereof,such as alumina mixed with one or more other oxides. Suitable oxidesinclude silica, titanium oxide, zirconium oxide, cerium oxide, tinoxide, trivalent rare-earth oxides, molybdenum oxide, cobalt oxide,nickel oxide, iron oxide, and the like, Activated alumina oralumina-based materials suitable for use herein include hydrated aluminacompounds such as hydrargillite, bayerite, boehmite, pseudoboehmite, andamorphous or substantially amorphous alumina gels. Exemplary alumina andalumina-based materials include aluminas which contain at least one ofthe phases taken from the group consisting of alpha, beta, delta, theta,kappa, gamma, eta, chi, rho, and mixtures thereof, as well as aluminasobtained by methods such as precipitation, rapid dehydration of aluminumhydroxides or oxyhydroxides, and/or calcining processes.

In accordance with aspects of the present disclosure, the catalystsand/or supports suitable for use with the process of FIGS. 1-2 typicallyhave a specific surface area ranging from about 1 m²/g to greater thanabout 800 m²/g, a mean pore diameter of the support of at least about0.1 and an average pore radius of about 20 Å or more. In this context,and within the framework of the present disclosure, the specific surfacearea is understood to be the BET surface area as defined by S. Brunauer,et al. [J. Am. Chem. Soc., Vol. 60; pp. 309 (1938)].

The catalysts of the present disclosure can further comprise a number ofadditives for improving their final chemical and/or mechanicalproperties. Such additives include inorganic constituents such as clays,silicates, ammonium sulfates, ceramic fibers, and asbestos; thickeningagents; surface-active agents; flocculating agents; and pore-formingagents. Thickening agents include cellulose, carboxymethyl cellulose,carboxyethyl cellulose, tallol, and xanthan gums. Flocculating agentsinclude polyacrylamides, carbon black, starches, stearic acid,polyacrylic alcohol, polyvinyl alcohol, biopolymers, glucose,polyethylene glycols, and the like.

Pore-forming agents include those agents that are added duringpreparation of the catalyst, but which disappear completely uponheating, thus creating the required macroporosity of the catalyst.Exemplary pore-forming compounds include, but are not limited to, woodflour, charcoal, sulfur, tars, plastics or plastic emulsions such aspolyvinyl chloride, polyvinyl alcohols, naphthalene, and combinationsthereof.

Additionally, the catalysts suitable for use in the processes of thepresent disclosure can be prepared by any known process foragglomerating, shaping or forming a catalyst or supported catalyst,including extrusion, pelleting/pelletization, granulation, and the like.Typically, the catalysts can be in any suitable shape, including beads,pellets, monoliths or agglomerates.

In some cases, environmental regulations will permit the discharge ofthe hot oxidized tail gas to the atmosphere. More commonly, the oxidizedtail gas will be subsequently cooled by various conventional means suchas, for example, indirect heat transfer to generate waste heat steam,followed by SO₂ recovery using various established processes.

The invention has been described in the context of preferred and otherembodiments and not every embodiment of the invention has beendescribed. Obvious modifications and alterations to the describedembodiments are available to those of ordinary skill in the art. Thedisclosed and undisclosed embodiments are not intended to limit orrestrict the scope or applicability of the invention conceived of by theApplicants, but rather, in conformity with the patent laws, Applicantsintends to protect all such modifications and improvements to the fullextent that such falls within the scope or range of equivalent of thefollowing claims.

All of the compositions, methods, processes and/or apparatus disclosedand claimed herein can be made and executed without undueexperimentation in light of the present disclosure. While thecompositions and methods of this invention have been described in termsof preferred embodiments, it will be apparent to those of skill in theart that variations may be applied to the compositions, methods,processes and/or apparatus and in the steps or in the sequence of stepsof the methods described herein without departing from the concept andscope of the invention. Further, it will be apparent that certain agentswhich are chemically related may be substituted for the agents describedherein while the same or similar results would be achieved. All suchsimilar substitutes and modifications apparent to those skilled in theart are deemed to be within the scope and concept of the invention.

1. (canceled)
 2. (canceled)
 3. (canceled)
 4. (canceled)
 5. A method for the destruction of ammonia (NH₃) from a sour water stripper in a sulfur recovery tail gas treating unit, the method comprising: first, combusting or thermally oxidizing an ammonia-bearing stream from a sour water stripper with air to destroy all or part of the ammonia contained in the feed stream and to generate hot combustion gases comprising one or more of N₂, NH₃, H₂S, SO₂, H₂O and/or H₂; second, combining the hot combustion gases with a tail gas stream from a Claus tail gas sulfur recovery unit comprising one or more of SO₂, S_(X), COS, CS₂, and/or CO to produce a hydrogenation reactor feed stream; and third, passing the hydrogenation reactor feed stream through a hydrogenation reactor so as to convert SO₂ and S_(x) to H₂S by catalytic hydrogenation, to convert COS and CS₂ to CO₂ and H₂S by catalytic hydrolysis, and to convert CO to CO₂ and H₂ by catalytic hydrolysis in the hydrogenation reactor; and thereafter, recovering H₂S from the hydrogenation reactor effluent stream in a sulfur recovery Tail Gas Treating Unit.
 6. The method of claim 5, wherein the ammonia-bearing stream is oxidized substoichiometrically.
 7. The method of claim 5, wherein combustion heat is partially removed, before or after combination of the combustion gases with the Claus tail gas stream(s), in cases where the NH₃ combustion heat release exceeds that required for proper catalytic hydrogenation and hydrolysis of the combined gas stream.
 8. The method of claim 5, wherein supplemental heat is imparted to the ammonia-bearing and/or Claus tail gas stream, either by inline combustion of a second fuel or indirect heat transfer, in cases where the NH₃ combustion heat release is less than that required for proper catalytic hydrogenation and hydrolysis of the combined gas stream.
 9. The method of claim 5, wherein the concentration and/or supply of the ammonia-bearing stream is insufficient for stable self-sustaining combustion, and supplemental inline combustion of a second fuel provides sufficient heat and O₂ for thermal oxidation of the ammonia-bearing stream.
 10. The method of claim 5, wherein residual NH₃ in the hydrogenation reactor effluent stream is recovered in downstream condensed water streams that are typically recycled for recovery of dissolved H₂S and/or NH₃.
 11. The method of claim 5, wherein the ammonia-bearing stream is combusted substoichiometrically and the hot combustion gases are subsequently exposed to an ammonia-cracking catalyst which promotes the dissociation of residual NH₃ to N₂ and H₂.
 12. The method of claim 5, wherein the hydrogenation catalyst is an alumina or silica gel substrate impregnated with compounds of cobalt or nickel and molybdenum.
 13. The method of claim 5, wherein combination of the hot combustion gases and the Claus tail gas stream results in a net temperature ranging from about 550° F. to about 650° F. to initiate the desired catalytic reactions.
 14. The method of claim 5, wherein the ammonia-bearing stream contains 0.01-100% NH₃ by volume.
 15. The method of claim 5, wherein the ammonia-bearing stream contains minor but significant concentrations of H₂S, mercaptans, HCN, hydrocarbons and/or unspecified organic contaminants.
 16. The method of claim 5, wherein NO_(x) formed by the combustion of the ammonia-bearing stream is converted to NH₃ and/or N₂ and H₂O within the hydrogenation reactor.
 17. The method of claim 5, wherein the hydrogenation reactor effluent is recycled as a minor feed stream to an external process for the recovery of NH₃ and/or H₂S.
 18. The method of claim 5, wherein the hot combustion gases are combined with a waste gas stream other than Claus tail gas comprising one or more of SO₂, S_(x), COS, CS₂, and/or CO.
 19. A method for the destruction of ammonia (NH₃) from a Claus tail gas unit, the method comprising: sub-stoichiometrically combusting an ammonia-bearing stream with air to generate hot combustion gases comprising one or more of NH₃, H₂S, SO₂, N₂, H₂O and H₂ in a first zone to generate a first zone effluent; combusting a second fuel in a second zone with sufficient excess air that residual O₂ exceeds the stoichiometric O₂ demand for complete oxidation of residual combustibles in the first zone effluent; combining the first zone and second zone effluents in a third zone; combining the third zone effluent with a Claus tail gas stream in a fourth zone resulting in a net temperature of 800-2000° F. sufficient to oxidize residual combustibles in the combined gas stream; adding additional air to the fourth zone as necessary to achieve the necessary oxidation of residual combustibles; and recovering SO₂ from the fourth zone effluent. 